Foam Flooding Research Articles

Effect of reservoir permeability on oil recovery using air foam flooding: a case study on Ganguyi oilfield

Air foam flooding is an important technology to enhance oil recovery by improving the swept volume of the fluid and the efficiency of displacement of oil. This study uses a literature review, engineering analysis of reservoirs, laboratory tests, and the data on oil production to clarify the relationship among the efficiency of oil displacement, control of the profile of the mechanism of water blockage, and the permeability of the reservoir. The results show that a highly permeable reservoir has a good pore structure with a large pore throat that helps yield a large swept volume and low interfacial tension to improve the efficiency of oil displacement. It also contains large pores that generate more foam for a higher oil mobility ratio and greater oil displacement. A heterogeneous reservoir has a strong Jamin effect and efficient oil displacement when air foam flooding is applied. The results of experiments yielded similar conclusions. The displacement efficiency of highly permeable and heterogeneous reservoirs is higher, and their injection pressure is lower when air foam flooding is applied. The permeability of reservoirs in oil fields should be higher than 1.5 mD for injection using air foam flooding. The results here can be used in applications of air foam flooding.

Hybrid surfactant-nanoparticles assisted CO2 foam flooding for improved foam stability: A review of principles and applications

Miscible carbon dioxide (CO2) flooding is a well-established and promising enhanced oil recovery (EOR) technique whereby residual oil is recovered by mixing with injected CO2 gas. However, CO2, being very light and less viscous than reservoir crude oil, results in inefficient sweep efficiency. Extensive research is ongoing to improve CO2 mobility control such as the development and generation of CO2/water foams. The long-term stability of foam during the period of flooding is a known issue and must be considered during the design stage of any CO2 foam flooding project. The foam stability can be improved by adding surfactants as stabilizers, but surfactants generated foams have generally a shorter life because of an unstable interface. Furthermore, surfactants are prone to higher retention and chemical degradation in the porous media, particularly under harsh reservoir conditions. Research has shown that nanoparticles (NPs) can act as an excellent stabilizing agent for CO2/water foams owing to their surface chemistry and high adsorption energy. The foams generated using NPs are more stable and provide better mobility control compared to surfactant-stabilized foams. One limitation of using NPs as foam stabilizers is their colloidal stability which limits the use of low-cost NPs. Combining surfactants and NPs for CO2 foam stabilization is a novel approach and has gained interest among researchers in recent years. Surfactants improve the dispersion of NPs in the aqueous phase and minimize particle aggregation. NPs on the other hand create a stable barrier at the CO2/water interface with the help of surfactants, thus generating highly stable and viscous foams. This paper presents a comprehensive review of the basic principles and applications of stabilized CO2 foams. A brief overview of CO2 foam flooding is discussed first, followed by a review of standalone surfactant-stabilized and NPs-stabilized CO2/water foams. The application of hybrid surfactant-NPs stabilized CO2 foams is then presented and areas requiring further investigation are highlighted. This review provides an insight into a novel approach to stabilize CO2/water foams and the effectiveness of the method as proved by various studies.

Fatty alcohol polyoxyethylene ether sulfonate for foam flooding in high-salinity and high-temperature reservoir conditions

Foam flooding can significantly improve the sweep efficiency of gas flooding by avoiding or weakening gas segregation, viscous fingering and gas channeling through areas of high permeability. However, most conventional anionic surfactants are not suitable to be used as foaming agents due to low tolerance to either high salinity or high temperature. In this paper, an anionic-nonionic combined surfactant, fatty alcohol polyoxyethylene (3) ether sulfonate (AEO3-HS) was synthesized, and its foaming performances at different conditions were examined. The results show that the foaming performance of the AEO3-HS is sensitive to crude oil which behaves as a defoaming agent. But this can be improved by mixing with cetyl dimethyl hydroxypropyl sulfobetaine (C16HSB). In mild reservoir conditions such as dissolved in simulated Daqing connate water (45 ℃, total salinity of 6778 mg/L, pH = 8–9) the AEO3-HS/C16HSB binary mixture at an optimal mole fraction ratio (0.6/0.4) and an optimal total concentration (4 mM) gives the maximum composite foaming index of 1100 Ls by shaking 10 mL solution with 0.25 g oil in a 100 mL cylinder. Moreover, the AEO3-HS/C16HSB binary mixture is well soluble in brine with 5000 mg/L CaCl2 + 100,000 mg/L NaCl at 60 °C, and does not hydrolyze in aqueous solution when stored at 90 °C for 3 months. In addition, the AEO3-HS and C16HSB molecules show attraction in mixed monolayer and the crude oil can be easily emulsified as small oil droplets dispersed in foaming solution during foaming process, which ensures the stabilization of the pseudo-emulsion films and thereby the foam stability in the presence of crude oil. The AEO3-HS synthesized is therefore a good candidate as foaming agent for high salinity and high temperature reservoirs.

Investigation of Nanoclay-Surfactant-Stabilized Foam for Improving Oil Recovery of Steam Flooding in Offshore Heavy Oil Reservoirs.

This study presents a study of nanoclay-surfactant-stabilized foam to improve the oil recovery of steam flooding in offshore heavy oil reservoirs. The foam stability and thermal resistance studies were first performed to investigate the influence of nanoclay on the stability and thermal resistance properties of the foam system. Then, the sandpack flooding tests were conducted for investigating the resistance factor and displacement abilities by nanoclay-surfactant-stabilized foam. The results showed that the nanoclay-surfactant-stabilized foam has excellent foaming ability and foam stability at 300 °C, which can be used in steam flooding for offshore heavy oil reservoirs. The resistance factor is greater than 30 at 300 °C when the gas–liquid ratio ranges from 1 to 3, which indicated that the nanoclay-surfactant-stabilized foam has good performance of thermal resistance and plugging effect. The heterogeneous sandpack flooding test showed that the nanoclay-surfactant-stabilized foam can effectively divert the steam into the low-permeability area and improve the sweep efficiency, thus improving heavy oil recovery of steam flooding. Therefore, the nanoclay-surfactant-stabilized foam flooding has a great potential for improving oil recovery of steam flooding in offshore heavy oil reservoirs.

Improved foam stability through the combination of silica nanoparticle and thixotropic polymer: An experimental study

Foam flooding serves as one of widely-used enhanced oil recovery (EOR) techniques for developing oil and gas resources. However, the foam is a thermodynamically unstable system, limiting its EOR performance. Hence, this study aims to provide a novel strategy to stabilize foam through the combination of nanoparticle and thixotropic polymer and tries to reveal the foam-stabilizing mechanism. Firstly, a novel water-soluble thixotropic polymer (WTP) was developed, which is able to thicken solution under low shear rates and become thin under high shear rates. Such thixotropic behavior helps to stabilize foams and has little effects on the stir-foaming process. Then the hydrophobic nano-SiO2 particles was modified by sodium dodecyl benzene sulfonate (SDBS) with the assistance of ultrasonic treatment. Coupled modified nano-SiO2 and WTP, this study develops a novel foam system with a high foaming volume and a long half-life time. This foam system is suitable for the high-temperature and high-salinity reservoir condition and can effectively enhance the oil recovery through foam flooding. The microscopic observations show that the foam system consists of fine, round and uniform bubbles, which may slow down the film drainage and restrain the gas diffusion. At the same time, the modified nano-SiO2 particles generate a “solid shell” on the bubble surface and improve the elasticity of foam film; the WTP forms molecular spatial networks in solution and mitigates the nanoparticle agglomeration. As a result, the synergistic effects of nano-SiO2 and WTP can improve the stability of foam significantly.

Flow Pattern and Resistance Characteristics of Gas–Liquid Two-Phase Flow with Foam under Low Gas–Liquid Flow Rate

To reduce the cost of arranging air foam flooding equipment at each wellhead, a method of establishing centralized air foam flooding injection stations is proposed. The flow pattern and resistance characteristics of air foam flooding mixtures in different initial conditions are studied. Experimental results indicate that the probability density function of stratified flow is obtained by comparing stainless steel and transparent pipes. If the gas–liquid ratio is kept constant, then the shape of the probability density function remains unchanged in both stainless steel and transparent tubes. Meanwhile, the flow pattern under the gas–liquid ratio is determined by comparing the image recognition results with the probability density function, and a formula for calculating the resistance and pressure drop of the gas and liquid two-phase flow in the horizontal and upward pipes is established. Compared with the experiments, the error results of the calculation are small. Thus, the proposed equations can be used to predict the flow resistance of real air foam flooding.

Synergistic Modes and Enhanced Oil Recovery Mechanism of CO2 Synergistic Huff and Puff

With the gradual declining of oil increment performance of CO2 huff-and-puff wells, the overall oil exchange rate shows a downward tendency. In this regard, CO2 synergistic huff-and-puff technologies have been proposed to maintain the excellent effect and extend the technical life of such wells. However, there is no specific research on the mechanism and synergistic mode of CO2 huff and puff in horizontal wells. This study aims to establish the synergistic mode and determine the adaptability and acting mechanism of CO2 synergistic huff and puff. Three synergistic huff-and-puff modes are proposed based on the peculiarity of the fault-block reservoir’s small oil-bearing area and broken geological structure. We establish three typical CO2 synergistic huff-and-puff models and analyze the influence of different geological and development factors on the huff-and-puff performance with numerical simulation. Each factor’s sensitivity is clarified, and the enhanced oil recovery (EOR) mechanism of CO2 synergistic huff and puff is proposed. The sensitivity evaluation results show that the reservoir rhythm, inter-well passage, well spacing, high-position well liquid production rate, and middle-well liquid production rate are extremely sensitive factors; the stratum dip and injection volume allocation scheme are sensitive factors; and the relationship with structural isobaths is insensitive. The EOR mechanism of synergistic huff and puff includes gravity differentiation, supplementary formation energy, CO2 forming foam flooding, and coupling effect of production rate and oil reservoirs. The implementation conditions of the two-well cooperative stimulation mode are the simplest. The two-well model is suitable for thick oil layers with a positive rhythm and large formation dip. The single-well mode requires no channeling between the wells, and the multi-well mode requires multi-well rows and can control the intermediate well’s fluid production rate. Field application at C2X1 block shows a good performance with a total oil increment of 1280 t and an average water-cut reduction of 57.7%.

Stabilization and performance of a novel viscoelastic N2 foam for enhanced oil recovery

A novel viscoelastic N2 foam (0.12% sodium dodecyl sulfate + 0.18% erucyl dimethyl amidopropyl betaine) with ultra-low interfacial tension and alkali-free was developed. With the conditions of Xinjiang Oilfield (45℃, c (salinity) = 7880 mg/L), the foam performances were investigated by the modified Rose-Miles method. The modified Rose-Miles method is in non-shear action, in which N2 enters a porous media and pumps into the solution to produce foam. The stability mechanism was explained based on the dilatational surface viscoelasticity and liquid viscoelasticity. The EOR effect was evaluated by the displacement experiment. The results showed that the foam volume of viscoelastic N2 foam was five times compared with the initial solution. The foam half-life and the drainage half-life were 6.5 and 6.2 times higher compared with that of stabilized by the polyacrylamide, respectively. The surface of N2 foam possessed high elasticity modulus, and the solution had high viscoelasticity, so the particle size and drainage of liquid film changed slowly. Finally, the viscoelastic N2 foam flooding (0.4PV surfactant + 0.4PV N2) enhanced oil recovery by 22.95%, compared with the surfactant flooding (0.8PV surfactant) by 4.06%. The viscoelastic N2 foam could greatly reduce the amount of surfactant and had an excellent EOR application in the Xinjiang Oilfield.

On the application of surfactant and water alternating gas (SAG/WAG) injection to improve oil recovery in tight reservoirs

Tight reservoirs are considered one of the unconventional hydrocarbon reservoirs with low permeability and porosity, directly affecting the oil production rate rather than conventional reservoirs. Thereby, optimum enhanced oil recovery methods would help petroleum industries produce more oil volumes from these reservoirs. In this study, different chemical and thermal enhanced oil recoveries methods such as surfactant alternating gas (SAG), water alternating gas (WAG), surfactant and foam flooding, and carbon dioxide (continuous and cyclic) were experimentally investigated to measure oil recovery factor. According to the results of this study, 3.5% of surfactant concentration, 0.15 PV of surfactant slug size, and 0.75 PV was selected as the total surfactant injection volume was selected as the optimum concentration for the injectivity performances. SAG scenario provided the highest oil recovery factor among all injectivity scenarios. It is about 54% that indicated the best efficiency of enhanced oil recovery methods in tight reservoirs rather than conventional recovery methods. The second highest oil recovery factor is dedicated to the WAG injectivity scenario regarding the feasibility of CO2 phase through porous media. It is about 46%. Moreover, due to the -gas phase in WAG and SAG, water cut had fluctuated as the water and gas had been alternatively injected into the core samples.

Application of orthogonal experiment method in foam flooding system composition and injection parameter optimization

Excellent composition and injection parameters of foam system are essential for foam flooding to exert mobility control. This study aims to optimize foam composition and injection parameters to maximize foam mobility control. The concentrations of foaming agent and stabilizer, oil saturation, foam quality, and flow rate served as influencing factors in the orthogonal experiment method with resistance factor (RF) as the evaluation index. Results showed that cores with different permeability levels corresponded to a set of optimal injection parameters. The optimal combination scheme significantly improved mobility control relative to all test groups in the orthogonal experiment, proving the effectiveness of this method in optimizing foam flooding parameters. During the analysis of orthogonal experimental data, in addition to the method of intuitive analysis was adopted to study the influence of a single factor on the RF, the influence of multiple factors interaction on the RF was also explored. Confirmatory tests were performed on the optimal parameters of foam flooding obtained by orthogonal experiments, and the foam propagation at different positions of the core was determined. The degree of pressure fluctuation during foam flooding was measured with the standard deviation ( SD ), which was used to directly measure the strength of the Jamin effect during foam flooding. The RF distribution factor ( D RF ) was introduced to describe the uniformity of foam seepage resistance along the core axis. D RF was used to study the entrance effect on foam to establish seepage resistance. The propagation performance of foam in porous medium is crucial to maximize its mobility control. Foam injectivity in porous medium should be given attention when optimizing the injection parameters of foam flooding. • Optimal injection parameters of foam are studied by orthogonal experiment method. • Obtained the influence trend of five factors on RF under various permeability levels. • Obtained multi-factors interaction effect on RF under various permeability levels. • Introduce SD and D RF to study the propagation characteristics of foam in cores.

Synergistic Effects between Anionic and Sulfobetaine Surfactants for Stabilization of Foams Tolerant to Crude Oil in Foam Flooding

AbstractIn foam flooding, foams stabilized by conventional surfactants are usually unstable in contacting with crude oil, which behaves as a strong defoaming agent. In this article, synergistic effects between different surfactants were utilized to improve foam stability against crude oil. Targeted to reservoir conditions of Daqing crude oil field, China (45 °C, salinity of 6778 mg L−1, pH = 8–9), foams stabilized by typical anionic surfactants fatty alcohol polyoxyethylene ether sulfate (AES) and sodium dodecyl sulfate (SDS) show low composite foam index (200–500 L s) and low oil tolerance index (0.1–0.2). However, the foam stability can be significantly improved by mixing the anionic surfactant with a sulfobetaine surfactant, which behaves as a foam stabilizer increasing the half‐life of foams, and those with longer alkyl chain behave better. As an example, by mixing AES and SDS with hexadecyl dimethyl hydroxypropyl sulfobetaine (C16HSB) at a molar fraction of 0.2 (referring to total surfactant, not including water), the maximum composite foaming index and oil tolerance index can be increased to 3000/5000 L s and 1.0/4.0, respectively, at a total concentration between 3 and 5 mM. The attractive interaction between the different surfactants in a mixed monolayer as reflected by the negative βs parameter is responsible for the enhancement of the foam stabilization, which resulted in lower interfacial tensions and therefore negative enter (E), spreading (S), and bridging (B) coefficients of the oil. The oil is then emulsified as tiny droplets dispersed in lamellae, giving very stable pseudoemulsion films inhibiting rupture of the bubble films. This made it possible to utilize typical conventional anionic surfactants as foaming agents in foam flooding.

Visualization study of polymer enhanced foam (PEF) flooding for recovery of waterflood residual oil: Effect of cross flow

Foam injection is an emerging EOR technology that increases oil recovery by reducing gas mobility, especially in heterogeneous reservoirs with permeability variations. Foam can divert flow from high permeability regions to low permeability regions, provided that its stability is high enough to maintain pressure. In this work, a visualization study of foam flow through a two-layer heterogeneous model is presented and the performance of a surfactant-polymer mixture as the foam stabilizer is evaluated. We compared the efficiency of conventional foam (stabilized by a surfactant) and polymer enhanced foam (PEF) flooding (stabilized by a combination of surfactant and PVA polymer) in the glass bead packed models with three permeability ratios (PR) including 2:1, 4:1, and 8:1. Our particular interest was to visualize the effect of the cross-flow mechanism on PEF performance. To achieve the desired permeability ratio, the model was packed with different sizes of glass beads ranging from 150 to 600 μm. The conventional foam and PEF were injected at the tertiary mode for the recovery of waterflood residual oil. Both foam and PEF injection were significantly more efficient than the gas injection; however, the PEF front advancement was more pistonwise; the ultimate oil recovery by PEF flooding was 15–20% more than the conventional foam flooding in all cases of heterogeneous packed models. At higher permeability contrast of the porous medium that the ability of the foam to sweep the porous medium decreases, the PEF still performs better through the cross-flow mechanism due to its higher stability. This makes the PEF injection a more decent candidate for fractured reservoirs where the heterogeneity contrast is high.

Influence of Heterogeneity on Nitrogen Foam Flooding in Low-Permeability Light Oil Reservoirs

The strong heterogeneity of (ultra)low-permeability light reservoirs such as the Tuha Oilfield has a serious impact on oil production. Nitrogen foam flooding is an effective means to improve oil re...

Laboratory evaluation of hybrid chemical enhanced oil recovery methods coupled with carbon dioxide

Chemically enhanced oil recovery techniques have been considered efficient tertiary methods to improve the oil production from oil reservoirs regarding their compatibility with the reservoir characteristics. Moreover, gravity segregation and viscous fingering during carbon dioxide flooding would be the main problems of oil recovery techniques. In this paper, a hybrid chemical flooding that contained the subsequent flooding of surfactant–polymer​ (henceforth; SP) coupled with supercritical carbon dioxide was performed to enhance the oil recovery factor. The foaming agent that is used in this experiment is solely formed by CO2. It is concluded that SP-foam flooding had witnessed the highest blockage, which is caused to have the maximum cumulative oil recovery factor (about 78%) due to the more mobilization oil in low permeable pores and cracks. Furthermore, direct foam flooding has the second-highest oil recovery factor (nearly 70%), which is considered as the preferable techniques to SP-CO2 flooding (65%). On the contrary, SP-foam flooding has provided the highest pressure drop after the minimum miscible pressure circumstances, which is about 0.27 MPa at the end of the process.

Monitoring of Flooding Characteristics with Different Methane Gas Injection Methods in Low-Permeability Heterogeneous Cores

Methane gas injected into reservoirs can greatly enhance oil recovery and has been widely used. However, continuous methane gas flooding has a deleterious effect on oil recovery enhancement and easily causes gas channeling in low-permeability heterogeneous reservoirs because of the low viscosity and high mobility of methane gas. This study consists of comprehensive experimental research that combines physical simulation and saturation dynamic monitoring technologies with a component analysis of produced oil to investigate the oil recovery and mobility control effects in low-permeability heterogeneous cores. First, solubility, foaming ability, and stability are used as evaluation indicators. The results show that an alcohol ethoxylate foaming agent at 1.5 wt % is suitable for reservoirs, based on the Waring blender and Ross–Miles methods combined with microscopic observation. Second, methods of methane gas with water alternating gas (WAG) injection, advanced cyclic water alternating gas (ACWAG) injection, and methane nonionic foam injection are performed on three kinds of low-permeability heterogeneous cores under reservoir conditions. The experimental results show that methane nonionic foam flooding can significantly improve oil recovery by 11–18%. Third, the residual oil saturation in the core is tested by saturation dynamic monitoring. This finding indicates that methane nonionic foam flooding reduces mobility control, effectively restrains gas channeling, increases sweep efficiency, and has the highest permeability plugging rate (82–90%) for high-permeability channels. In the stage of methane WAG and ACWAG flooding, methane gas can increase the C12–C24 components in the produced oil by 0.3–0.9%. ACWAG injection can improve the stage of no water-cut oil recovery compared with conventional WAG injection.

In-situ formulation of pickering CO2 foam for enhanced oil recovery and improved carbon storage in sandstone formation

Compared to sole gas flooding, foam flooding provides superior mobility control, enhanced sweep, and greatly improved oil recovery from depleted oil reservoirs. However, since most modern oil reservoirs are located at higher depths and further away from foam generation units, it is becoming increasingly difficult to maintain foam stability, especially in modern deeper oil wells. Thus, in this study, an alternative study in foam formulation has been reported. Instead of preparing the foam at the surface and injecting it down the oil well, into the subsurface, the foam can be formed “in situ” by saturating the porous media downhole by foaming agents. The foaming agents in this study consisted of an anionic surfactant, sodium dodecyl sulfate (SDS), and the whole solution was stabilized by the addition of 1000 ppm PAM and varying concentrations of silica nanoparticles (NPs). The formed foam can then be pushed conventionally by chase water and provide increased oil recovery. Increasing NP concentration, initially improved foam stability as a higher number of NPs participated in strengthening the gas bubble. Insitu foam formation was also investigated for improving carbon storage in depleted oilfields. The injection rate of gas and the slug size of the foaming agent were varied to determine gas storage before the breakthrough. A lower flow rate was found to be more conducive for foam formation while increasing slug size had little effect on gas storability in the reservoir.

Experimental Study on Improving Oil Displacement Efficiency by Air Foam Flooding in Tight Oil Layer

The tight oil layer is poor in physical property, small pore throat radius, serious heterogeneity of reservoir, low flooding efficiency, poor water flooding efficiency and final recovery is lower than 10%. In order to further improve the oil displacement yield and simulate the conditions of oil layer, we have carried out the experiment of air foam liquid system to flooding oil, and studied the rule of improving the displacement efficiency of air tight foam reservoir. The experimental results show that the density of Gaotaizi water flooding ultimate oil displacement efficiency is 48.95% on average, after water flooding to air - foam flooding alternating final displacement efficiency is high up 79.63%, the oil displacement efficiency can be increased by 26.92%; a short alternately displacement than the big slug is better, the gas-liquid ratio is too high, the breakthrough time of change in short, flooding effect, direct air - foam liquid slug can achieve good flooding effect. That air foam flooding can improve the oil displacement efficiency of dense oil after water flooding by air - foam liquid slug, gas-liquid ratio, cycle injection parameter optimization, to further improve the dense oil displacement effect, the results of air foam flooding field test has the reference and guiding significance for the tight reservoir.

Field Application of Steam Foam Flooding in Foreign Oilfields

Field Application of Steam Foam Flooding in Foreign Oilfields

Study on aerobic corrosion characteristics of gas injection pipe wall in oil field under dry / wet interaction condition

By studying the corrosion behavior of oilfield pipelines in different oxygen content and corrosive medium under simulated ambient air/air foam flooding environment, the dry/wet interaction between the surface and the interface of the service casing is caused by the air displacement/air foam flooding, which greatly aggravates the aerobic corrosion process. The corrosion process changed from localized corrosion to uniform corrosion with the increase in dry and wet cycles. Pitting corrosion occurs in the early stages of dry and wet cycles, and the increase in chloride concentration and oxygen content will accelerate the initiation and development of pitting.

Flow behaviors of nitrogen and foams in micro-visual fracture-vuggy structures.

Nitrogen gas flooding and foam flooding have been widely used for oil and gas development in fracture-vuggy carbonate reservoirs. However, flow behaviors of nitrogen and foams are not very clear owing to the complex connectivity of fractures and vuggys. In this work, four types of micro-visual fracture-vuggy models were designed and fabricated to systematically investigate the dynamic flow behaviors of nitrogen and foam in fracture-vuggy structures. Results indicate that the swept volume and oil displacement efficiency can be improved more by foam flooding than by nitrogen flooding owing to the abilities of foams on mobility adjustment, IFT reduction, and oil emulsification. The presence of vuggy can strengthen the effect of gravity differentiation during nitrogen flooding, while foam flooding can diminish the gravity differentiation effect. Besides, pressure difference at the curved oil–gas interface plays a great role in the flow characteristics of nitrogen and foam. Moreover, the EOR rate is used to evaluate the EOR potential of nitrogen foam flooding technology over nitrogen flooding technology. This work systematically reveals the dynamic flow behaviors of nitrogen and foam in various micro visual fracture-vuggy structures, which can provide theoretical support for the development of the fracture-cavity reservoir.